In conventional gas fields, where the gas is held volumetrically in the pores of the reservoir and where the gas can flow relatively easily to the producing wells, production can be monitored using pressure-volume relationships. As gas is produced, the pressure reduces concomitantly with the reduction in remaining gas volume, and flow rate reduces concomitantly with decreasing pressure. A typical plot of P/Z against cumulative gas production (where P is the reservoir pressure and Z is the gas compressibility factor) allows production data to be interpreted in terms of the amount of gas that is in contact with the producing well (i.e. the amount of gas being drained by the producing well), how much of the gas has been produced to date, and (assuming pressure cut-offs) an estimate of how much gas will be produced ultimately. Any decision to drill an infill gas well can usually be based on a reasonable prediction of the likely remaining gas volume to be accessed by the infill well.
Natural gas may be found associated with coal in a coalbed methane (CBM) reservoir. In such CBM reservoirs, the gas is not stored in pore spaces but is adsorbed onto the structure of the coal. Production is initiated by reducing the pressure (initially by pumping water from the CBM reservoir), so that the natural gas (predominantly methane) begins to desorb from the coal and to move, initially through micropores in the coal, towards a producing gas well. The pressure-volume-rate relationships from a producing gas well of a CBM reservoir are therefore very different to those from a conventional gas well. In particular, gas flow rate from a producing gas well of a CBM reservoir may increase as pressure decreases, and may continue at a steady rate or even at an increasing rate for years before finally declining.
A similar situation arises in tight gas reservoirs, for example, tight gas sands and tight shale gas reservoirs wherein the term “tight” means that the natural gas is contained within a very low permeability reservoir rock from which natural gas production is difficult. Typically, the rock of a tight gas reservoir has an effective permeability of less than 1 millidarcy. The tighter the rock (i.e. the lower its permeability), the greater the effect that the rock matrix has on holding the gas, and the more tortuous the network of fine pores through which the gas must flow before it can be produced. Accordingly, it is difficult to estimate the contacted volume (i.e. the volume of the reservoir that is being drained by a gas well) and recovery factor using gas production data from tight gas reservoirs.
Studies of tight gas reservoirs that have producing gas wells at different spacings show that closer infill spacings give progressively smaller incremental gas recoveries. This is because the infill locations have been partially depleted owing to production from existing wells. Such studies based on analogue data (obtained from analogous tight gas reservoirs having similar rock matrix, reservoir pressure etc.) can estimate, on average, the value of infill wells for a tight gas reservoir, but it is much more difficult to estimate the recoverable volume for a specific infill well location and hence the value of the infill well location.